1. Field Of The Invention
The present invention relates to compositions and methods for treating subterranean formations. Specifically, the invention is directed to compositions used to break fracturing fluids utilized in the stimulation of subterranean formations.
2. Description Of The Prior Art
It is common practice to treat subterranean formations to increase the gross permeability or conductivity of such formations by procedures which are identified generally as fracturing processes. For example, it is a conventional practice to hydraulically fracture a well in order to produce one or more cracks or "fractures" in the surrounding formation by mechanical breakdown of the formation. Fracturing may be carried out in wells which are completed in subterranean formations for virtually any purpose. The usual candidates for fracturing, or other stimulation procedures, are production wells completed in oil and/or gas containing formations. However, injection wells used in secondary or tertiary recovery operations, for example, for the injection of water or gas, may also be fractured in order to facilitate the injection of fluids into such subterranean formations.
Hydraulic fracturing is accomplished by injecting a hydraulic fracturing fluid into the well and applying sufficient pressure on the fracturing fluid to cause the formation to break down with the attendant production of one or more fractures. The fracture or fractures may be horizontal or vertical, with the latter usually predominating, and with the tendency toward vertical fracture orientation increasing with the depth of the formation being fractured. Usually a gel, an emulsion or a foam, having a proppant such as sand or other particulate material suspended therein is introduced into the fracture. The proppant is deposited in the fracture and functions to hold the fracture open after the pressure is released and the fracturing fluid flows back into the well. The fracturing fluid has a sufficiently high viscosity to retain the proppant in suspension or at least to reduce the tendency of the proppant to settle out of the fracturing fluid as the fracturing fluid flows along the created fracture. Generally, a gelation agent and/or an emulsifier is used to gel or emulsify the fracturing fluid to provide the high viscosity needed to realize the maximum benefits from the fracturing process.
When the fracturing fluid is to be utilized in a formation having a temperature above about 175.degree. F., and particularly those formations having a temperature above about 225.degree. F., a stabilizer is added to the gel. The stabilizer generally functions to scavenge oxygen from the fluid and to assist in preventing premature gel degradation. The use of sodium thiosulfate and similar compounds as gel stabilizers is well known in the art. The method is described in, for example, U.S. Pat. No. 3,146,200.
After the high viscosity fracturing fluid has been pumped into the formation and fracturing of the formation occurred, it is desirable to remove the fluid from the formation to allow hydrocarbon production through the new fractures. Generally, the removal of the highly viscous fracturing fluid is realized by "breaking" the gel or emulsion or, in other words, by converting the fracturing fluid into a low viscosity fluid. Breaking the gelled or emulsified fracturing fluid has commonly been accomplished by adding a "breaker," that is, a viscosity-reducing agent, to the fracturing fluid prior to pumping into the subterranean formation. However, this technique can be unreliable and sometimes results in incomplete breaking of the fluid, particularly when gel stabilizers are present and/or premature breaking of the fluid before the fracturing process is complete.
Conventional oxidizing breakers such as sodium or ammonium persulfate are useful to reduce the viscosity of a fracturing fluid at temperatures up to about 175.degree.-200.degree. F., but tend to cause the fluid to break too rapidly at higher temperatures resulting in premature loss of viscosity. Premature breaking can decrease the number or length of fractures obtained and thus, the amount of hydrocarbon recovery.
The incorporation of a gel stabilizer into a fracturing fluid to provide high temperature stability often interferes with the ability of a breaker to provide a desired viscosity reduction in the fracturing fluid and the breaker sometimes interferes with the ability of the stabilizer to stabilize the gel for the desired period of time within the subterranean formation. Further, it is known in the art that most fracturing fluids will break if given enough time at an elevated temperature even in the presence of a gel stabilizer. However, it is, of course, most desirable to return the well back to production as quickly as possible, therefore, it generally is desired to break a gel within 6 to 24 hours after introduction into a subterranean formation.
There remains a need for a method for effecting controlled breaking of a fracturing fluid when a gel stabilizer is present.